1. Field of the Invention
The present invention relates to development of underground reservoirs, such as hydrocarbon reservoirs comprising a fracture network. In particular, the invention relates to a method for characterizing the fracture network and constructing a representation of the reservoir. The representation is used to optimize the management of development through a prediction of the fluid flows likely to occur through the medium to simulate hydrocarbon production according to various production scenarios.
2. Description of the Prior Art
The petroleum industry, and more precisely exploration and development of reservoirs, notably petroleum reservoirs, require knowledge of the underground geology which is as perfect as possible so as to efficiently provide evaluation of reserves, production modelling or development management. In fact, determining the location of a production well or of an injection well, the drilling mud composition, the completion characteristics, selection of a hydrocarbon recovery method (such as waterflooding for example) and of the parameters required for implementing this method (such as injection pressure, production flow rate, etc.) requires good knowledge of the reservoir. Reservoir knowledge notably means knowledge of the petrophysical properties of the subsoil at any point in space.
The petroleum industry has therefore combined for a long time field (in-situ) measurements with experimental modelling (performed in the laboratory) and/or numerical modelling (using softwares). Petroleum reservoir modelling is a technical stage that is essential for any reservoir exploration or development procedure. The goal of modelling is to provide a description of the reservoir.
Fractured reservoirs are an extreme type of heterogeneous reservoirs comprising two very different media, a matrix medium containing the major part of the oil in place and having a low permeability, and a fractured medium representing less than 1% of the oil in place and highly conductive. The fractured medium itself can be complex, with different sets of fractures characterized by their respective density, length, orientation, inclination and opening.
Those in charge of the development of fractured reservoirs need to perfectly know the role of fractures. What is referred to as a “fracture” is a plane discontinuity of very small thickness in relation to the extent thereof, representing a rupture plane of a rock of the reservoir. On the one hand, knowledge of the distribution and of the behavior of these fractures allows optimizing the location and the spacing between wells to be drilled through the oil-bearing reservoir. On the other hand, the geometry of the fracture network conditions the fluid displacement, on the reservoir scale as well as the local scale where it determines elementary matrix blocks in which the oil is trapped. Knowing the distribution of the fractures is therefore also very helpful at a later stage to the reservoir engineer who wants to calibrate the models which have been constructed to simulate the reservoirs in order to reproduce or to predict the past or future production curves. Geosciences specialists therefore have three-dimensional images of reservoirs allowing locating a large number of fractures.
Thus, in order to reproduce or to predict (that is “simulate”) the production of hydrocarbons when starting production of a reservoir according to a given production scenario (characterized by the position of the wells, the recovery method, etc.), reservoir engineers use a computing software referred to as reservoir simulator (or flow simulator) that calculates the flows and the evolution of the pressures within the reservoir represented by the reservoir model. The results of these computations enable prediction and optimization of the reservoir in terms of flow rate and/or of amount of hydrocarbons recovered. Calculation of the reservoir behavior according to a given production scenario constitutes a “reservoir simulation”.
There is a well-known method for optimizing the development of a fluid reservoir traversed by a fracture network, wherein fluid flows through the reservoir are simulated through simplified but realistic modelling of the reservoir. This simplified representation is referred to as “double-medium approach”, described by Warren J. E. et al. in “The Behavior of Naturally Fractured Reservoirs”, SPE Journal (September 1963), 245-255. This technique considers the fractured medium as two continua exchanging fluids with one another: matrix blocks and fractures which is referred to as a “double medium” or “double porosity” model. Thus, “double-medium” modelling of a fractured reservoir discretizes the reservoir into two superposed sets of cells (referred to as grids) making up the “fracture” grid and the “matrix” grid. Each elementary volume of the fractured reservoir is thus conceptually represented by two cells, a “fracture” cell and a “matrix” cell, coupled to one another (i.e. exchanging fluids). In the reality of the fractured field, these two cells represent all of the matrix blocks delimited by fractures present at this point of the reservoir. In fact, in most cases, the cells have hectometric lateral dimensions (commonly 100 or 200 m) considering the size of the fields and the limited possibilities of simulation softwares in terms of computing capacity and time. The result thereof is that, for most fractured fields, the fractured reservoir elementary volume (cell) comprises innumerable fractures forming a complex network that delimits multiple matrix blocks of variable dimensions and shapes according to the geological context. Each constituent real block exchanges fluids with the surrounding fractures at a rate (flow rate) that is specific thereto because it depends on the dimensions and on the shape of this particular block.
In the face of such a geometrical complexity of the real medium, the approach is for each reservoir elementary volume (cell), in representing the real fractured medium as a set of matrix blocks that are all identical, parallelepipedic, delimited by an orthogonal and regular network of fractures oriented in the principal directions of flow: For each cell, the so-called “equivalent” permeabilities of this fracture network are thus determined and a matrix block referred to as “representative” (of the real (geological) distribution of the blocks), single and of parallelepipedic shape, is defined. It is then possible to formulate and to calculate the matrix-fracture exchange flows for this “representative” block and to multiply the result by the number of such blocks in the elementary volume (cell) to obtain the flow on the scale of this cell.
It can however be noted that calculation of the equivalent permeabilities requires knowledge of the flow properties (that is the conductivities) of the discrete fractures of the geological model.
It is therefore necessary, prior to constructing this equivalent reservoir model (referred to as “double-medium reservoir model”) as described above, to simulate the flow responses of some wells (transient or pseudo-permanent flow tests, interferences, flow measurement, etc.) on models extracted from the geological model giving a discrete (realistic) representation of the fractures supplying these wells. Adjustment of the simulated pressure/flow rate responses on the field measurements allows the conductivities of the fracture families to be calibrated. Although it covers a limited area (drainage area) around the well only, such a well test simulation model still comprises a very large number of calculation nodes if the fracture network is dense. Consequently, the size of the systems to be solved and/or the computation time often remain prohibitive.